Crude oil and natural gas residing in subterranean porous formations are produced by drilling wells into the formations. Oil and/or natural gas flow into the well driven by the pressure gradient which exists between the formation and the well, by gravity drainage, by fluid displacement, and by capillary action. Typically, surface pumps are required to supplement the natural driving forces to bring the hydrocarbons to the surface.
Most wells are hydraulically fractured to increase flow. The drill pipe casing section adjacent to the zone to be fractured is perforated using explosive charges or water jets. Then a fracturing fluid is pumped down the drill pipe and into the formation at a rate and pressure high enough to fracture the formation. The fractures propagate as vertical and/or horizontal cracks radially outward from the well bore.
Solid particles called proppants are dispersed into the fracturing fluid and are carried by the fluid into the formation. Proppants lodge in the propagated fractures and hold the fractures open after the hydraulic pressure on the fracturing fluid is released and the fracturing fluid flows back into the well. Without proppants, the cracks would close and the increased conductivity gained by the fracturing operation would be lost.
The primary consideration in selecting a proppant is the pressure in the subterranean formation to be fractured. Suitable proppants include sand, graded gravel, glass beads, sintered bauxite, resin coated sand and ceramics. In formations under moderate pressure, 6000 psi or less, the most commonly used proppant is ordinary screened river sand. For formations with closure stresses 6000 to about 10,000 psi, sand proppants coated with a thermosetting phenolic resin are preferred. Sintered bauxite, glass beads and ceramics are used to fracture wells with closure pressure in the range of 10,000 to 15,000 psi.
The rheological requirements of a fracturing fluid are highly constraining. To adequately propagate fractures in the subterranean formation, the fracturing fluid must have sufficient body and viscosity to form fractures without leaking excessively into the formation. Also, a fracturing fluid must have the capability to transport and deposit large volumes of proppant into the cracks in the formation formed during fracturing. After the fracturing operation is complete and pressure on the fluid is released, the fracturing fluid must readily flow back into the well and not leave residues that impair permeability of the formation and conductivity of the fracture. Finally, a fracturing fluid must have rheological characteristics which permit it to be formulated on the surface with reasonable convenience and be pumped down the well without excessive difficulty or pressure drop friction losses.
The most commonly used fracturing fluids are water-based compositions containing a water soluble hydratable high molecular weight polymer which increases the viscosity of the fluid by forming a gel when it dissolves in the fluid. Thickening the fluid reduces leakage of liquids from the fracturing fluid into the formation during fracturing and increases proppant suspension capability.
A wide variety of hydratable water soluble polymers are used in fracturing fluid formulations including polysaccharides, polyacrylamides, and polyacrylamide copolymers. Polysaccharides are currently favored. Particularly desirable polysaccharides include galactomannan gum and cellulose derivatives. Preferred polysaccharides include guar gum, locust bean gum, carboxymethylguar, hydroxyethylguar, hydroxypropylguar, carboxymethylhydroxypropylguar, carboxymethylhydroxyethylguar, hydroxymethyl cellulose, carboxymethylhydroxyethyl cellulose and hydroxyethyl cellulose. Generally, the molecular weights of the hydratable polymers used in fracturing fluids range from about 500,000 to about 3,000,000. The ratio of apparent viscosity of the fracturing fluid relative to water at shear rates encountered in well fractures is between about 50 to about 2000. Viscosifier concentrations in fracturing fluids range from about 10 to about 100 lbs. of viscosifier per 1000 gallons of fracturing fluid.
Over the years, producers have drilled oil and gas wells to ever increasing depths to maintain reserves and production. Downhole temperatures increase with well depth and since the viscosity of fracturing fluids decrease with increasing temperature, formulations of fracturing fluids had to be modified to maintain fluid performance. Initially, the reduced viscosity of fracturing fluids at downhole conditions was compensated by increasing the concentration of hydratable polymer in the fracturing fluids. However, at current well depths, the viscosifier concentrations required to maintain adequate viscosity at downhole conditions are so high that the fracturing fluid is too viscous at ambient surface conditions to formulate and pump. The solution was to add chemical agents to the fracturing fluid which crosslink the polymer viscosifier molecules. Cross-linking increases fluid viscosity by forming chemical bonds between viscosifier polymer molecules.
The crosslinks form between cis position hydroxyl groups on adjacent polysaccharide thickener polymer molecules. Common crosslinking agents include polyvalent ions in their high valance state such as Al(III), Ti(IV), Zr(IV) in the form of salts of organic acids. Also, borate ions are effective crosslinkers for polysaccharides. The preferred cross-linking agents include zirconium and, titanium acetate, and zirconium and titanium lactate. The concentration of cross-linker typically is in the range of from about 1% to 10% by weight of polymer. The cross-linking agent is added to the fracturing fluid.
The activity of crosslinking agents increase with temperature so that crosslinking is delayed until the fracturing fluid heats as it approaches the formation. The fracturing fluids are formulated so that the cross-linking reaction is not completed until after the fracturing fluid flows into the subterranean formation. Accordingly, the viscosity of the fracturing fluid is low at the surface permitting the fluid to be easily formulated and pumped into the well and the fluid viscosity increases as the fluid flows into the subterranean formation where the higher viscosity is required.
When the fracturing operation is complete, the pressure of the fracturing fluid in the formation is reduced. Fracturing fluid flows back out of the formation into the well. It is imperative that the fracturing fluid flow quickly and completely out of the formation and back into the well to allow production of hydrocarbons. To enhance back flow of fracturing fluid out of the formation and into the well, it is necessary to reduce or "break" the viscosity of the fracturing fluid so that the fluid can flow freely.
Hydratable polymers decompose spontaneously in time from either bacteriological or thermal degradation, but these natural degradation modes are slow and too much production time would be lost if producers waited for natural degradation processes to break the fracturing fluid viscosity. To accelerate fracturing fluid viscosity reduction, a chemical agent referred to as a "breaker" is added to the fracturing fluid. Breakers operate by severing the backbone chain of the hydrated polymer.
It is critical that the viscosity breaking process does not occur before the fracturing process is completed. The breaker must effectively reduce fracture fluid viscosity, but only after the fracturing is complete. Breaking agents are water soluble components which are typically added to the fracturing fluid at the surface as the fracturing fluid is formulated. Depending on the type, the breaker may begin decomposing the viscosifying polymer as the fracturing fluid flows down the well and into the formation. If the breaker reduces viscosity of the fracturing fluid prematurely, fracture formation, proppant transport capability and fluid leakage control into the formation can all be impaired. Clearly, striking a balance between effectiveness and timeliness of the action of breaker is significant and difficult.
Enzyme breakers such as alpha and beta amylases, amyloglucosidase, oligoglucosidase invertase, maltase, cellulase, and hemicellulase are commonly used for wells having a bottomhole temperature below about 150.degree. F. and with fracturing fluids with pH between about 3.5 and 9. Enzymes catalyze the hydrolysis of glycosidic bonds between the monomer units of polysaccharides.
Peroxygen compounds are the preferred breakers for higher temperature downhole temperatures in the range from about 140.degree. F. to about 250.degree. F. temperature range. They form free radicals which attack and sever the backbone of gel polymer chains. Peroxides generally decompose over a narrow temperature range characteristic of the peroxide. Accordingly, the common practice is to select a peroxide breaker which decomposes at the temperature range of the subterranean formation to be fractured.
Commonly used peroxygen breakers include dichromates, permanganates, peroxydisulfates, sodium perborate, sodium carbonate peroxide, hydrogen peroxide, tertiarybutylhydroperoxide, potassium diperphosphate, and ammonium and alkali metal salts of dipersulfuric acid, alkali and alkaline earth percarbonates and persulfates and perchlorates. Preferred breakers include ammonium and alkali and alkaline earth persulfates such as ammonium, sodium and potassium persulfate. Typical breaker addition rates range from about 0.1 to 10 lbs. per thousand gallons of fracturing fluid. Breakers are usually added to the fracturing fluid at the surface "on-the-fly" as the fluid is being pumped down the well.
Persulfates break viscosity by thermally decomposing into highly reactive sulfate free radicals which attack the polymer backbone. Thermal decomposition of persulfates is slow below 125.degree. F., but accelerates as temperature increases in the range from about 150.degree. F. to 225.degree. F. Typically, the higher the formation temperature the lower the concentration of persulfate breaker in the fracturing fluid
Surface active agents (surfactants) are commonly added to fracturing fluids to promote back flow of fracturing fluid out of the subterranean formation to the well after fracturing is complete. Surfactants promote return flow of fracturing fluid by lowering interfacial tension and capillary pressure in the formation fissures, and dispersing gas bubbles which form in the formation interstices to block return flow of fracturing fluid. Surfactants also disperse residual fragments of decomposed hydratable polymer into the fracturing fluid to promote their removal from the formation along with the fracturing fluid.
Fracturing fluids are formulated to limit water leakage from fracturing fluids into the formation during fracturing because water can permanently damage formations. The mechanism by which fluid leakage in well fracturing is controlled can be analogized to filtration. When fracturing is initiated, some of the fracture fluid unavoidably flows into the formation. But, as the fracturing operation proceeds, fluid leakage into the matrix is progressively restricted by continuous deposition of the polymer gel thickening agents used in fracturing fluids. The thickening agents form a thin film over the fracture face which is referred to in the fracturing technical literature as a "filter-cake." Ideally, when the fracturing operation is complete, the breaker decomposes the gel polymer molecules in the fracture fluid and in the filter-cake. Polymer gel fragment residues agglomerate into large particles which reduce the conductivity of the fracture for flow of oil and gas and thus impair production.
The surfactant disperses the polymer residue fragments into the fracturing fluid and prevents them from agglomerating so that the residual polymer fragments are flushed out of the formation along with the back flowing fracturing fluid after the fracturing operation is complete. However to effectively promote dispersal and removal of polymer fragment residues the surfactant must be in relatively high concentration in the zones where the breaker decomposes polymer gel, both in the fracturing fluid and in and around the gel filter-cake.
For the foregoing reasons there is a need for a breaker system for aqueous fracturing fluids comprising a hydratable polymer wherein the breaker system will: a) effectively decompose the hydratable polymer molecules both in the fluid and in the filter cake; b) but not until the fracturing operation is complete; and c) and wherein the breaker system will deliver surfactant in sufficient concentration to emulsify and suspend the residual gel polymer fragments in the fracturing fluid and preclude agglomeration of the polymer fragments.